In accordance with the VDER Phase One Order, each utility in the state submitted an Implementation Proposal addressing calculation and compensation methodologies for Distributed Energy Resources (“DERs”). The Implementation Order largely approves the utilities’ Implementation Proposals, with certain modifications relating to the recovery of VDER costs, the methodology behind the Installed Capacity credit, and the calculation of Market Transition Credits. The Order also addresses certain issues associated with the Value Stack for DERs and cost mitigation.

In general, solar energy advocates have reacted negatively to the Implementation Order. They assert that there is significant variation in how utilities calculate their respective Utility Marginal Cost of Service (MCOS), which is used to establish demand reduction value (DRV) and locational system relief value (LSRV) for DERs in their service territories. Because the DRV and LSRV inform the overall Value Stack associated with DERs, solar advocates claim that DER compensation will vary wildly from utility to utility. To illustrate this point, they note that proposed utility MCOS values range from $226/kW (Con Edison) to $15/kW (Central Hudson). While the Commission’s Order acknowledges the desire among some commentators for a more standardized valuation methodology, it concludes that Phase One is too early to implement such measures and instead will consider this issue as part of VDER Phase Two.

Solar energy advocates also have expressed concerns that the utilities’ regular recalculation of DRVs and LSRVs based on their latest MCOS studies would not provide the kind of rate certainty that potential investors in DERs require. While the Implementation Order states that such dynamic pricing is necessary to promote efficiency, solar energy advocates counter that it is not stable enough to provide reliable pricing signals to investors. In response to this comment, the NYPSC agreed to fix a DER’s DRV for 3 years and LSRV for 10 years from the date on which a DER project achieves certain interconnection milestones.

The NYPSC, however, also took steps towards reducing development costs for DERs by initiating processes to increase the maximum size of DER projects from 2 MW to 5 MW and to facilitate consolidated billing systems. The Commission also delayed adopting proposed compensation structures for storage systems that are paired with eligible generation resources and set the Environmental Value for eligible projects at the latest Tier 1 REC procurement price published by NYSERDA at the time when the project’s developer makes the 25% interconnection payment required under the Standard Interconnection Requirements, or, if no such payment is required, then the time at which an interconnection agreement is signed.

The Implementation Order provides a timeline for next steps, which include the filing of utilities’ Value Stack tariffs and Staff recommendations on storage paired with eligible generation. New York’s utilities must file tariff amendments incorporating the modifications discussed in the Implementation Order with an effective date of November 1, 2017. The Implementation Order also provides that work to refine and improve the Value Stack, expand VDER eligibility, and address rate design issues remains ongoing as part of VDER Phase Two.

Recent trends demonstrate a rapid growth in corporations directly buying renewable energy from wind, solar and other renewable energy generators. Renewable energy capacity under corporate power purchase agreements (PPAs) doubled each year from 2012 to 2015. For wind energy generation, corporate purchasers constituted 52% of capacity contracted through PPAs in 2015, up from only 5% in 2013. Many corporations are looking to increase reliance on renewable power to meet internal sustainability or environmental policies, and dramatic decreases in renewable costs have increasingly made renewables competitive with traditional power sources. The long-term nature of most PPAs can be attractive to businesses seeking the stability of fixed electricity costs, while renewable developers gain a dependable off-taker, often a critical component of securing financing.

This trend was punctuated by the recent announcement by MGM Resorts International that it plans to pay $86.9 million for the ability to exit Nevada Power’s utility service and purchase its own electricity on the wholesale market. Some states, including Nevada, require approval from state regulators and the payment of an exit fee before being able to purchase power directly from generators across utility transmission lines. As the largest purchaser of energy from Nevada Power (at nearly 5% of annual energy sales), MGM determined it was worth paying the substantial exit fee to control its ability to directly purchase renewable power.

Corporate purchasing of renewables is growing across a variety of sectors and markets. Large corporations contracted for 3.6 gigawatts (GW) of power in 2015 and the first quarter of 2016, a three-fold increase over 2014. Small and mid-sized corporations may lack resources or buying power to support stand-alone PPAs, but recent trends suggest a growing market for aggregating resources. A group of nonprofit organizations in the US, called the Renewable Energy Buyers Alliance (REBA), has been formed to facilitate the process of grouping smaller companies together to achieve economies of scale. And while large technology companies have led the way in recent years, pharmaceuticals, industrials, and retailers have also entered the renewable energy market.

Overall, with the rapidly falling price in renewables and corporate policies encouraging more sustainable business practices, it appears likely that the rise of corporate renewable PPAs will continue.

This post was prepared with the assistance of Eric Hanzich in the Orange County office of Latham & Watkins.

The end of the California State Legislature’s regular session for the year culminated in a frenzy of action, with Assembly members scrambling to pass dozens of bills before midnight on September 12, 2015. The California Legislature voted on a package of 12 bills addressing environmental and health concerns, such as off-shore drilling, divestment of investment funding from coal companies, water quality, energy efficiency in disadvantaged communities, and increased public transportation. This post analyzes three of the more significant and controversial bills proposed this year, including last minute changes to each during the final week of the session: SB 350; SB 32; and AB 1288.

The most far-reaching climate change goals of the climate bill package were enshrined in SB 350. The proposed bill, authored by Senate President Pro Tempore Kevin de León and Senator Mark Leno, originally called for a 50 percent reduction in petroleum use in cars and trucks, a 50 percent increase in energy efficiency in buildings, and for 50 percent of the state’s utility power to be derived from renewable energy, all by 2030; termed the “50-50-50” formula.

These standards paralleled Governor Jerry Brown’s climate change agenda for the year, which was first announced during his inaugural address in January. Last Wednesday, following a failure to garner the necessary votes amid resistance from moderate Democrats, state legislative leaders amended SB 350 to drop requirements for a 50 percent reduction in petroleum use for cars and trucks. As modified, the bill passed on a 52-27 vote.

Despite the removal of the petroleum reduction provision, which garnered headlines, SB 350 represents a sweeping expansion of renewable energy and energy efficiency mandates. The bill requires the state to double energy efficiency savings in electricity and natural gas by retail customers by 2030 and increases the Renewables Portfolio Standards (RPS) so that half of the state’s electricity must be procured from renewable sources by 2030, which remain groundbreaking measures in themselves.

California’s RPS was originally established in 2002 under SB 1078. In 2011, Governor Brown signed legislation to increase the RPS to 33 percent by the year 2020 (SB 2-1X Chapter 1 Statutes of 2011). Currently, most energy utilities have bought or have built enough energy resources to meet the 33 percent RPS before the target year. SB 350 continues the effort to boost renewable energy use by increasing the RPS to 50 percent by the year 2030. As per current law, the 50 percent renewable energy standard will be implemented by the California Public Utilities Commission (CPUC) for investor-owned utilities (IOUs) and other retail sellers subject to CPUC jurisdiction , and by the California Energy Commission (CEC) for publicly-owned utilities (POUs).

SB 350 is fairly comprehensive in setting forth a regime to implement and evaluate procurement plans, including a renewable energy procurement plan, that each retailer of electricity (IOUs, POUs, community choice aggregation and energy service providers) must provide on an annual basis. In addition, they each must regularly file an integrated resource plan (IRP) for approval. Other than for POUs, these IRPs will be reviewed by the CPUC. The governing body of the POU will approve the IRP subject to review by the CEC.

SB 350 is quite specific as to what factors must be considered in proposed procurement plans and provides (in a nod to the challenges presented when attempting to integrate intermittent energy sources) that the goals must be balanced by the need to have just and reasonable rates, to ensure system and local reliability, to preserve the resilience of the electric grid, and to enhance distribution system management. Those goals are exemplified by a provision that requires the CPUC to identify a “balanced portfolio of resources” to ensure “reliability” and “optimal integration” of renewables, and requires that utilities include in their procurement plans a “strategy for procuring best-fit and least cost resources” to meet the portfolio needs the CPUC identifies. The review of the CPUC’s balanced portfolio and of the utilities’ proposed strategies will be battlegrounds in which any entity that has an economic interest in the transformation of the grid will have a stake in the outcome.

Notably, transportation electrification must be addressed in the IRPs. Indeed, widespread transportation electrification is now “the policy of the state” and a legislatively-recognized means to achieve both ambient air quality standards and the state’s climate goals. SB 350 implicitly acknowledges the uncertainty in how rapidly and how extensively the transportation system will be electrified, as well as the potential increase in retail sales and related greenhouse gas (GHG) emissions. Accordingly, SB 350 provides that RPS enforcement can be waived if a retail seller demonstrates that it missed its RPS target due to transportation electrification exceeding demand forecasts. Similarly, SB 350 lays the groundwork for retail sellers to receive an additional allocation of Cap-and-Trade Program allowances from the California Air Resources Board (ARB).

SB 350 requires the doubling of energy efficiency but, in doing so, tries to bring some coherence to the concept of “energy efficiency savings.” It provides guidance as to what measures qualify and requires an evaluation of feasibility and cost effectiveness in setting annual targets for those savings. SB 350 also requires the CEC to adopt a responsible contractor policy and establish consumer protection guidelines.

The bill expands the mandate of the California Independent System Operator (CAISO) to permit it to enter into compacts with states within the Western Electricity Coordinating Council (WECC) and to, thereby, become a regional system operator along the lines of the PJM[i]. This will ultimately require further legislation once CAISO develops new by-laws and will require the willingness of other states to participate in the new organization, which could result in a new grid operator/ISO to manage the flow of electricity for portions of the Pacific/Western region. This is consistent with the ambitions of the CAISO, but also provides another tool for California to minimize the cost of an abundance of renewable power during times of the day when it is not needed. CAISO demonstrated with its recently implemented Energy Imbalance Market that utilities who are not under the jurisdiction of the CAISO see an economic benefit in selling into and buying from the California energy market.

On September 8, members of the State Assembly rejected a bill that would have amended AB 32, the Global Warming Solutions to Act, to codify GHG emissions reduction targets for 2030 and 2050. Passed in 2006, AB 32 requires the state to reduce GHG emissions to 1990 levels by 2020. Two executive orders set emissions reduction targets for subsequent years—Governor Brown’s Executive Order B-30-15 requires reduction of GHG emissions levels to 40 percent below 1990 levels by 2030, and Governor Schwarzenegger’s Executive Order S-3-05 requires a reduction of GHG emissions to 80 percent below 1990 levels by 2050.

In June, the Senate passed a version of SB 32, introduced by Senator Pavley, which would have codified the executive orders’ 2030 and 2050 GHG emissions reduction targets, and would have authorized ARB to set an interim target for 2040. Last Tuesday, however, SB 32 failed to pass in the Assembly in a 35-30 vote. The bill was amended later in the week to remove the 2050 target and authorization for ARB to set a 2040 standard. Despite the amendment, the Assembly shelved the revised bill, though it may take it up again next year.

Although SB 32 failed in the Assembly last week, CEQA may nonetheless require GHG sections of EIRs to analyze a project’s consistency with Executive Order B-30-15’s 2030 emissions reduction target and Executive Order S-3-05’s 2050 target. As discussed in a previous post, late last year the Court of Appeal struck down San Diego County’s Climate Action Plan, in part for failing to analyze post-2020 GHG reductions targets.[ii] In addition, the Supreme Court is currently considering a similar issue in Cleveland Natl. Forest Found. v. San Diego Assn. of Governments, in which the Court of Appeal held that SANDAG violated CEQA by failing to discuss the proposed regional transportation plan’s consistency with state climate policy, as reflected by Executive Order S-3-05, and related mitigation measures.[iii]

The Legislature passed a significantly scaled down version of Assembly Bill (AB) 1288, which adds two new members to the ARB. Pursuant to the new bill, the Senate Committee on Rules and the Speaker of the Assembly will each appoint one member to work with communities that are significantly burdened by, and vulnerable to, high levels of pollution, including communities with diverse racial and ethnic populations and communities with low-income populations.

As passed, AB 1288 looks little like the original version, which was introduced by Speaker Toni Atkins (D-San Diego). Atkins’ proposed bill would have removed the sunset date for further GHG reductions in California’s Cap-and-Trade Program. Although this measure was stricken from the final bill, ARB has long expressed its intention to extend the Cap-and-Trade Program beyond 2020. Indeed, ARB just this week announced that it is holding a public workshop on October 2, 2015 to discuss, among other things, potential regulatory amendments necessary for a post-2020 Cap-and-Trade Program.

Summary

The Legislature’s failure to pass SB 32 and the amendments made to SB 350 and AB 1288 have been noted by some political commentators as significant setbacks for Governor Jerry Brown’s ambitious climate and energy agenda. At a press conference following the news that the 50 percent target for reduction in petroleum use would be dropped from SB 350, Brown appeared defiant. He promised to use ARB’s existing authority to achieve both the 50 percent petroleum reduction goal proposed by SB 350 and the GHG emissions reduction targets proposed by SB 32, which he believes can be implemented through the Low Carbon Fuel Standard, Zero Emission Vehicle Program, as well as the Cap-and-Trade Program. Since they would not be codified under state law, however, the petroleum and GHG emissions reduction targets could later be rescinded or changed by a future governor who disagrees with Governor Brown’s executive orders. Moreover, regulated parties and other affected industry groups may not share the Governor’s perspective on the extent of ARB’s existing authority, leading to potential administrative and judicial challenges should ARB press forward without the Legislature’s blessing.

[i] The PJM is the regional transmission organization that coordinates the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.

As California begins to turn the page on the first chapter of its efforts to combat climate change through AB 32 and to prepare for greater emissions reductions over the coming decades, the California Energy Commission (CEC) and California Public Utilities Commission (CPUC) are considering what these changes will mean for electricity transmission infrastructure. To that end, CEC Chair Robert Weisenmiller and CPUC President Michael Picker sent a letter to Cal-ISO President and CEO Stephen Berberich on July 31, 2015 asking him to participate in the planning stages of the Renewable Energy Transmission Initiative (RETI) 2.0. Since 2008, the first iteration of RETI has served as a statewide initiative to identify and implement the energy transmission projects needed to accommodate California’s renewable energy requirements.

Now, with Governor Brown’s executive order to cut California’s greenhouse gas emissions by 2030 and a number of legislative proposals advancing to set further greenhouse gas emissions reductions targets for 2030 and beyond, as well as the US EPA’s federal Clean Power Plan encouraging regional coordination among states to increase renewable electricity production, the CEC and CPUC feel that the time has come to bring RETI up to date.

Citing previous successes of the RETI program, including the Sunrise Powerlink (a high-voltage transmission line for renewable energy that was employed at full capacity by renewable sources within one year of electrification and served as a critical power source for Southern California following the closure of the San Onofre nuclear power plant), Weisenmiller and Picker maintain that identifying additional potential transmission corridors around the state will be essential to further increasing the state’s renewable capacity. With significant renewable energy production set to occur in California’s southeastern desert region as part of the Desert Renewable Energy Conservation Plan, additional transmission lines to transport this energy to population centers will be critical in coming years.

Anticipating and planning for the needs of the state’s evolving energy market will, however, require more than constructing new transmission lines. In their letter to Cal-ISO, Weisenmiller and Picker noted that it would be critical to give careful consideration “to existing transmission capacity that may be freed up as older, less efficient conventional power plants decommission, [allowing] for additional low-carbon options to take their place.” Balancing new and old transmission infrastructure will be complex and data-intensive, illustrating why RETI 2.0 will be so important to California’s shifting energy needs in the coming decades.

Complicating things still further, the federal Clean Power Plan, released shortly after the July 31 RETI 2.0 letter, encourages greater coordination and communication among states across the region, incentivizing them to work together to increase renewable energy use. For California, this represents an opportunity, because states to its east reach peak load several hours earlier. Thus, with adequate transmission lines in place, California could export clean electricity (e.g., from utility-scale solar farms) to these states during the beginning of their peak consumption hours and import wind energy from the Midwest and Great Plains when those states are past peak (but wind capacity is high) and California’s energy needs are at their peak. Anticipating such increasing levels of interstate coordination, CEC and CPUC have expressed interest in engaging regional stakeholders in the RETI 2.0 planning process, while still respecting the jurisdiction of regulators in other states around the West.

CEC and CPUC anticipate that the planning process for RETI 2.0 will take place over the coming year, beginning with a joint agency workshop to introduce RETI 2.0, which took place on September 10. The joint workshop addressed subjects including transmission planning and the particular challenges of planning transmission for renewable energy, how best to approach environmental analysis in the context of statewide planning for renewable energy, and an overview of lessons learned from RETI 1.0. The agencies have also planned a series of workshops with CalISO, beginning in October, to engage with interested stakeholders, Native American tribes, and federal, state, and local agencies.

The public can post comments about RETI 2.0 to the CEC’s website until 4:00 p.m. on September 24, 2015; the comment page is available here. The agencies aim to have recommendations for the 2030 Renewables Portfolio Standard ready by the fall of 2016.

Latham & Watkins LLP will continue to monitor these developments as they unfold.

President Obama recently announced that the Department of Energy (DOE) Loan Program Office (LPO) is expanding support for innovative “distributed energy projects” by adding $1 billion in available loan guarantees to support the deployment of these projects through the existing solicitations for Renewable Energy and Efficient Energy Projects and Advanced Fossil Energy Projects. Eligible projects could include energy storage, smart grid technologies, cogeneration and methane capture for oil and natural gas wells, as well as roof-top solar and energy efficiency technologies that meet certain “innovation” requirements. For example, roof-top solar projects that are combined with storage may be eligible.

The LPO also is targeting distributed energy developers with special supplements to these two pending solicitations that make clear that existing program authority under Title XVII of the Energy Policy Act of 2005 and resources may be used to accelerate the deployment of distributed energy projects. The credit enhancement available through DOE’s LPO traditionally has been used to support utility-scale energy projects. In recognition of the important role of distributed energy in the future of US energy markets, the LPO is making a concerted effort to marshal program resources to support innovation in this growing segment.

In connection with the announcement, DOE’s LPO also released new guidance clarifying that state and state-affiliated entities, such as state green banks, may apply for loan guarantees for eligible projects under Title XVII, which encompasses both the Renewable Energy and Efficient Energy Projects and the Advanced Fossil Energy Projects solicitations. In the special supplements to these solicitations, the LPO explained that distributed energy projects “require different financial structures” than the utility-scale projects that have been supported by Title XVII guarantees. State green banks may serve an important role facilitating and structuring multi-party distributed energy projects. The LPO announcement also notes that projects with state backing may be particularly competitive for a Title XVII loan guarantee if such state support reduces the riskiness of the proposed project.

Through the supplements to the existing solicitations for Renewable Energy and Efficient Energy Projects and Advanced Fossil Energy Projects, DOE’s LPO has made clear that distributed energy projects and state (or state-affiliated) green bank entities are encouraged to apply for loan guarantees through these solicitations. Further, DOE has provided potential applicants with more information about financial structures, project arrangements and distributed energy technologies that are eligible to apply for and potentially obtain guarantees through these solicitations. The LPO accepts applications under these solicitations on a rolling basis.